This section provides background information to facilitate a better understanding of the various aspects of the disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.
Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, commonly referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore is drilled, various forms of well completion components may be installed in order to control and enhance the efficiency of producing the various fluids from the reservoir. Well treatment methods often are used to increase hydrocarbon production by using a chemical composition, such as a treatment fluid.
Stimulation operations may be performed to facilitate production of fluids from subsurface formations by increasing the net permeability of a reservoir. There are two main stimulation techniques: matrix stimulation and fracturing. Matrix stimulation is accomplished, typically in sandstone rich formations, by injecting a fluid (e.g., acid or solvent) to dissolve and/or disperse materials that impair well production. Specifically, matrix stimulation may be performed (1) by injecting chemicals into the wellbore to react with and dissolve the damage and (2) by injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (e.g., instead of removing the damage, redirecting the migrating oil around the damage). Fracturing involves injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbon can more readily move from the formation and into the wellbore.
In carbonate formations, the goal of matrix stimulation is to create new, unimpaired flow channels from the formation to the wellbore. Matrix stimulation, typically called matrix acidizing when the stimulation fluid is an acid, generally is used to treat the near-wellbore region. In a matrix acidizing treatment, the acid used (for example hydrochloric acid for carbonates) is injected at a pressure low enough to prevent formation fracturing. When injected at low rates into carbonate formations, the acid can form conductive wormholes that extend radially from the wellbore. Acids can also be injected into subterranean formation at rates high enough to cause fracturing. In this case, the acid unevenly dissolves the walls of the fracture, so that when the injection is stopped and the fracture closes, conductive channels to the well remain.
One of the problems often encountered in the application of acids, especially inorganic acids, at elevated carbonate reservoir temperatures, is their excessive reaction rate toward carbonate originating from a lack of restriction to the mobility of the protons. For example, HCl is very reactive, and at higher temperatures (such as 200° F. and higher) and/or low injection rates, favors facial dissolution over wormholing. For this reason, less reactive acid formulations have been pursued. One approach is to use organic acids such as formic and acetic acid. Organic acids have higher pKa's than HCl, but will not completely spend in the reservoir. A second approach is to suspend the acid as a water-in-oil emulsion, which restricts aqueous acid contact with the reservoir and thus slows the reaction rate.
Numerous approaches have been applied toward retarding the acid reactivity, mainly via physical means. For example, it is common in oilfield operations to encapsulate inorganic acid into shells of polymer gel, linear or crosslinked, or light oils in the presence of surfactant and/or chelating agent. Each of these options offers a certain level of performance, but at the same time brings several undesirable side effects.
At present, acid treatments are plagued by two primary limitations namely, limited radial penetration and severe corrosion to pumping and wellbore tubing. Both effects are associated with the higher-than-desired reaction rate (or spending rate) of inorganic acids, such as HCl, toward carbonate surface, in particular at higher temperatures. Limitations on radial penetration are caused by the fact that as soon as the acid, in particular inorganic acids, such as by nonlimiting example, HCl, is introduced into the formation or wellbore, it reacts instantaneously with the formation matrix and/or the wellbore scaling. In practice, the dissolution is so rapid that the injected acid is spent by the time it reaches no more than a few inches beyond the wellbore, incapable of generating much desired fracture length far from the wellbore. Organic acids (e.g., formic acid, acetic acid and/or lactic acid and its polymeric version) are sometimes used to address limitations on radial penetration since organic acids react more slowly than inorganic acids. Increasingly, retarded acid systems, which use techniques such as gelling the acid, oil-wetting the formation, or emulsifying the acid with oil, are used. Each of such alternatives, however, has associated drawbacks and is an imperfect solution to limited radial penetration.
Other limitations related to the use of acids are: 1) very high miscibility of acids with water when the potential for undesirable migration of the acid-bearing fluid into a water-saturated zone is a concern; and 2) iron precipitation, especially in sour wells, where the iron sulfide scale formed in boreholes, tubulars, and/or formations is dissolved by the acid with the formation of hydrogen sulfide (H2S) and undesirable iron precipitates such as ferric hydroxide or ferrous sulfide that affect the permeability of the formation. Therefore, acid treatment fluids often contain additives to minimize iron precipitation and H2S evolution, for example by sequestering the iron ions in solution, or by reducing ferric ions to the more soluble ferrous form of iron.
The performance of a fracture acidizing treatment job may be measured by the length of the fracture that is effectively acidized. The distance a reactive acid travels along the fracture (e.g., acid penetration depth), is governed by the acid flow (injection) rate and the acid reaction (spending) rate at the rock surface. In most of the circumstances encountered in acid treatment, the reaction rate between acid and rock is very fast, and the rate determining step is acid mass transfer from bulk to rock surface.
In fracture acidizing, the treatment fluid used is injected at a pressure high enough to cause formation fracturing, designed to open sustained flowpath network that connects limestone and/or dolomite reservoirs to the wellbore. In order to achieve deeper penetration in fracture acidizing, it is often desirable to retard the acid in such treatments as well. Common approaches to acid retardation for fracture acidizing include gelling, emulsifying and to a minor extent chemical intervention. Each of these methodologies brings certain advantages that are invariably accompanied by a set of disadvantages. For example, gelled acids provide moderate retardation in the temperature range of 80 to 200° F. As gels exhibit high viscosity and low friction loss, they function primarily as diverting agents, contributing to fluid loss reduction. In addition, the use of an emulsified acid that is applied to the fracture acidizing treatment of limestone and dolomite up to 300° F. Emulsified acid has the disadvantage of longer spending times and subsequent problems of cleaning due to the presence of residual oil. It is also common practice to retard acid using surfactants, although limited acid retardation is obtained. However, the deployment of surfactant also carries a few unwanted effects. For example, it could strip any existing coating on carbonate surfaces and as such act as an accelerator. Therefore, retardation schemes relying on surfactant films are often unreliable and ineffective. Furthermore, the attempt to use biodegradable, solid acid precursors such as polylactic acid in acidizing treatments has been plagued by the intrinsic disadvantage of very small acid capacity, leading to prohibitive costs and cumbersome dependency on formation temperature range which governs the rate of degradation.